This invention relates to retrofitting mooring systems, as used in the subsea oil and gas industry, to upgrade the capacity of their subsea foundations to resist tension in mooring lines.
A poster published in Offshore Magazine, October 2013, entitled Mooring systems for offshore floating installations: trends and technology provides a comprehensive overview of the mooring technologies known in the art. That poster may be viewed online at http://www.offshore-mag.com/content/dam/offshore/print-articles/Volume%2073/10/MOORING-010814REV.pdf
Floating surface units or installations used in oil and gas production are moored to the seabed to remain in substantially the same location for many years of production. An example of such an installation is an FPSO (Floating Production, Storage and Offloading) vessel.
Some taut-leg floating production units are known but these require reinforced anchorages to be installed at the outset, which is generally achieved by injecting concrete or grout. The present invention is concerned with the more common catenary mooring lines that have generally catenary curvature when viewed in profile.
Typically, an FPSO will be held in place by a mooring system comprising catenary-shaped mooring lines arranged in groups to define semi-taut legs. When viewed from above, the mooring lines splay apart from neighbouring mooring lines in each group to define a passive spread pattern.
Usually there is one group of mooring lines at each quadrant of an FPSO, hence a total of four groups, radiating outwardly at 90° intervals when viewed from above. If each of the four groups contains three mooring lines, for example, this is known in the art as a 4×3 pattern. Some surface installations, such as turret-moored vessels, are moored with three groups of mooring lines, radiating outwardly at 120° intervals when viewed from above.
FIGS. 1 and 2 show one of the mooring lines 10 of a conventional mooring system for an FPSO 12 floating at the surface 14, as an example of a moored surface installation. The mooring line 10 hangs with catenary curvature under tension between the FPSO 12 and the seabed 18. Whilst curved, the mooring line 10 lies substantially in a vertical plane.
In this example, the mooring line 10 is anchored by a suction anchor or suction pile 16. Most of the length of the pile 16 is embedded in the soil of the seabed 18 to ensure sufficient resistance to tension in the mooring line 10 when the FPSO 12 moves back.
It will be apparent from FIGS. 1 and 2 that the mooring line 10 is attached to the pile 16 at a level below the mid-point of the length of the pile 16, typically between half and two-thirds of the way down from the top of the pile 16. A similar arrangement is also shown, for example, in WO 02/062653 to a predecessor of the Applicant. This arrangement optimises the balance of forces that act on the pile 16: connecting the mooring line 10 at or nearer to the top would tend to cause rotation of the pile 16, which would require a bigger pile to withstand a given tension in the mooring line 10.
It follows that a short bottom part of the mooring line 10, typically 10 m to 20 m long, is buried in the soil of the seabed 18 beside the pile 16. That buried bottom part is sometimes called a ‘forerunner’.
A drag anchor, also embedded in the seabed 18, may be used instead of a pile 16 as a mooring foundation for a surface installation such as an FPSO 12. Again, a short bottom part of the mooring line 10 will similarly be buried in the soil of the seabed 18 if a drag anchor is used.
In more detail, the mooring line 10 comprises, in sequence from bottom to top: a bottom or ground chain 20 attached to the pile 16; a section of spiral strand wire (SSW) 22 attached to the ground chain 20; and a top chain 24 that joins the SSW section 22 to the FPSO 12.
The SSW section 22 will usually be of coated steel but could be of a synthetic plastics material instead: references to ‘wire’ in this specification are not intended to limit the meaning only to metallic wires.
The SSW section 22 constitutes most of the length of the mooring line 10 because, for a given tensile strength, wire is lighter, more compact to store and less expensive than chain. Chains 20, 24 are used instead of wire at the bottom and top of the mooring line 10 to avoid damage to the wire at those vulnerable locations. As a non-limiting example, the ground chain 20 and the top chain 24 may each be about 200 m long whereas the SSW section 22 may be well over 1200 m long.
Various known connectors 26 join the successive components of the mooring line 10. Different types of connector 26, such as chain connectors and shackles, will typically be used at different locations along the mooring line 10.
It will be apparent from the detail view of FIG. 2 that the ground chain 20 is in two sections, namely a lower section 28 and an upper section 30. Thus, in sequence from the bottom to the top of the mooring line 10: the lower section 28 of the ground chain 20 is attached to a buried side wall of the pile 16; the upper section 30 of the ground chain 20 is connected to the lower section 28 by a first connector 26; the SSW section 22 is connected to the upper section 30 of the ground chain 20 by a second connector 26; and the top chain 24 is connected to the SSW section 22 by a third connector 26.
The lower section 28 of the ground chain 20 is attached to the pile 16 before the pile 16 is overboarded from a surface installation vessel and lowered to penetrate the seabed 18. Thus, the lower section 28 of the ground chain 20 and the first connector 26 are buried under the seabed 18 as part of the bottom ‘forerunner’ part of the mooring line 10.
The upper section 30 of the ground chain 20 extends from the buried first connector 26 beneath the seabed 18 to the second connector 26 above the seabed 18, where it joins the SSW section 22. Thus, a short transitional portion of the upper section 26 of the ground chain 20 lies on or close to the seabed 18.
A drawback of the partially-buried ground chain 20 arises from inevitable movement of the ground chain 20, in use, relative to the surrounding soil of the seabed 18. For example, all parts of the mooring line 10, including the ground chain 20, will move in response to motion of the FPSO 12 under wind and wave action. Similarly, all parts of the mooring line 10 will be moved by other seawater dynamics acting on the mooring system, such as ocean currents, especially in deeper water.
The resulting movements of the ground chain 20 also move the adjacent soil of the seabed 18. Over time, this may create a trench without soil around and above the previously-buried part of the ground chain 20 beside the pile, hence potentially reducing the capacity of the pile 16. Similarly, a drag anchor could slip and lose its intended position. The result is that, after several years, the actual capacity of the foundation may be significantly lower than was originally intended.
In other cases, the tension applied by a mooring line to a foundation may be greater than was originally intended. For example, the floating surface installation may be enlarged or a mooring line handling system may be upgraded.
For these reasons, it may be necessary to upgrade the capacity of a subsea foundation from time to time. Upgrading capacity may involve recovering original capacity that has been lost by a foundation over time. Alternatively, or additionally, upgrading capacity may involve improving the original capacity of a foundation.
Conventionally, upgrading the capacity of a subsea foundation involves installing a new, more efficient foundation in the seabed near the old foundation. Next, part of the mooring line is disconnected from the old foundation to reconnect it to the new foundation. The old foundation is then redundant.
Disconnecting a mooring line from an existing foundation, or even slackening a mooring line to reduce tension, disadvantageously increases the load on other parts of the mooring system. It is a lengthy and costly operation that introduces a risk of the surface installation losing its position, especially if sea conditions deteriorate during the operation.
WO 2008/129320, to a predecessor of the Applicant, discloses a frame that is used for connecting mooring line elements on the seabed. In a reverse operation, the frame can also be used to separate mooring line elements. The frame comprises pulling means to connect mooring line elements. However, the mooring line elements cannot have residual tension in them. Thus, the frame of WO 2008/129320 cannot be used on a live tensioned line; a line from the floating surface installation must first be slackened.
U.S. Pat. No. 5,061,131 discloses an alternative approach involving extra weights that sharply increase mooring resistance in the event of extreme drift. However, the possible size of such weights is limited on a permanent mooring and in any event would not provide a sufficient upgrade in tension-resisting capacity. Also, the weights apply a permanent shear stress to the mooring lines.
WO 94/16936 relates to a twin-anchor mooring arrangement for a floating vessel, in which a first drag anchor is attached at an end of a mooring line and a second drag anchor is slidable along the mooring line to a second anchoring position.
US 2009/123235 relates to a pile anchor system for an offshore structure. The system includes an original pile attached to a mooring line, and a supplementary pile installed in the vicinity of the original pile. The supplementary pile is attached to the original pile by means of a coupling member, but is not attached to the mooring line itself.
U.S. Pat. No. 7,976,246 describes a system for creating a deep water mooring spread by successively installing independent suction piles from a floating vessel.